OTC 22065
Petroleum Systems of the Russian Western Arctic Basins
T.A. Kiryukhina, A.V. Stoupakova, G. Ulyanov, N. Kiryukhina, D. Norina, A.A. Suslova
Lomonosov Moscow State University
Copyright 2011, Offshore Technology Conference
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Abstract
The structure of the Arctic Eurasian basins suggests that petroleum systems of Palaeozoic, Mesozoic and
Cenozoic age may be present. Palaeozoic petroleum systems are well studied in the northern part of the Timan-Pechora.
On the Barents-Kara shelf Palaeozoic petroleum systems are forecast, but no related hydrocarbon accumulations have
been discovered, although the Palaeozoic section contains source rocks able to generate hydrocarbons. Mesozoic
petroleum systems are studied in the Barents Sea and the Yamal Peninsula. They relate to Lower, Middle and Upper
Triassic gas and oil source rocks, Middle Jurassic oil and gas source rocks and very rich Upper Jurassic oil source rocks.
The formation of the petroleum systems and the oil and gas potential of the basins is directly dependent on the
basins’ structure and geological history. Palaeozoic intracratonic rifting increased the heat flow of the basin and resulted
in oil and gas kitchens in the extensional parts of the basins. Fault tectonics allowed vertical migration of fluids.
In the deep sag basins, like the Central Barents, South Kara and North West Siberia basins, filled by both
Palaeozoic and Mesozoic strata the Mesozoic petroleum systems provide significant volume of hydrocarbon, but they are
influenced by Palaeozoic petroleum systems. In the Palaeozoic basins, such as Timan-Pechora, Svalbard and, probably,
North Kara, the petroleum systems are linked with hydrocarbon migration from the deep Palaeozoic horizons or adjacent
Mesozoic basins.
Hydrocarbon generation started long before the present basins’ structural configuration formed, and oil and gas
kitchens were associated mainly with extensional parts of the basins. Later phases of rifting and extension affected both
the ancient oil and gas kitchens and the younger ones. Inversion caused trapping and affected fluid migration, mixing the
petroleum systems. Inverted structures in the old rifts have the highest potential for large hydrocarbons accumulations but,
in highly uplifted areas affected by faulting and erosion, exploration risk is high. Forecasting hydrocarbon distribution
needs profound understanding of the geological evolution of petroleum basins, their structural units and petroleum
systems, which control the location of giant fields.
Introduction.
The Russian Western Arctic Basins cover the huge area including the Barents and Kara seas, the western part of the
Laptev sea and adjacent territories with some archipelagoes and islands (Spitsbergen, Franz Josef Land, Severnaya
Zemlya, Novaya Zemlya, etc.). They comprise the Barents and Kara Basins, the northern areas of the Timan-Pechora
Basin, the North West Siberia, including Yamal and Gidan peninsulas and the Yenisey-Khatanga Basin (Fig.1,2).
The Russian Western Arctic Shelf Basins are potential for exploration of hydrocarbons as confirmed by the
discoveries of the giant and large gas fields like Shtokmanovskoye in the Barents Sea, Rusanovskoye and Leningradskoye
in the Kara Sea, gas condensate fields on the Yamal peninsula, oil and gas fields in the Pechora Sea and YeniseyKhatanga basin. All the sedimentary basins on the Arctic Shelf have an intracratonic setting and have been formed by
several phases of tectonism (Fig. 3). All of them are deep extensional basins (sag basins), where sediments are 8 - 15 km
thick or more. The base of the crust (“Moho” boundary) varies from 40-42 to 33-35 km. The basins are filled by mainly
Palaeozoic and Mesozoic sedimentary successions. Cenozoic successions are thick and prospective only on the
continental margin slopes.
Fig.1 Russian Western Arctic location
Fig.2 Russian Western Arctic Basins
The structure of the Arctic Eurasian basins suggests that petroleum systems of Palaeozoic and Mesozoic age may
be present. Palaeozoic petroleum systems are well studied in the northern part of the Timan-Pechora. On the Barents-Kara
shelf Palaeozoic petroleum systems are forecast, but no related hydrocarbon accumulations have been discovered,
although the Palaeozoic section contains oil source rocks able to generate hydrocarbons. Mesozoic petroleum systems are
studied in the Barents Sea and the Yamal Peninsula. They relate to Lower, Middle and Upper Triassic gas and oil source
rocks, Middle Jurassic oil and gas source rocks and very rich Upper Jurassic oil source rocks.
Pechora Sea Petroleum Systems.
Pechora Sea contains hydrocarbons (HC) in the Palaleozoic strata and Lower –Middle Triassic reservoirs. There
are three main petroleum systems in the basin: Ordovician – Lower Devonian clastic-carbonate, Upper Devonian Frasnian
– Famennian – Lower Carboniferous siliceous carbonate and Carboniferous – Permian carbonate-clastic (table 1; fig.4).
The Ordovician – Lower Devonian clastic-carbonate group relates to Upper Silurian source rocks of type II – III.
The total organic carbon (TOC) content varies from 0.23 to 4% (Kiryukhina et al. 2006). Oil occurs in Upper Silurian –
Lower Devonian dolomites in the Trebsa, Titova and Upper Vozey fields. Stratigraphic traps are expected. Porosity
reaches over 20% and permeability varies from 10 - 100 mD. The area contains Lower Devonian shale seals.
The Upper Devonian –Lower Carboniferous petroleum system relates to Upper Devonian Middle Frasnian
siliceous carbonate shales, Domanic formation, which is the main hydrocarbon source rocks for the most Upper
Palaeozoic fields in the Timan-Pechora Basin. Upper Devonian source rocks of the Pechora Sea have provided HC for the
main offshore fields, like Dolginskoye oil and gas field, Prirazlomnoye oil field and Varandey more oil field. The primary
source rock interval of the Upper Devonian source rock is about 100 m, which is located beneath the Upper DevonianLower Carboniferous carbonate buildups. The Upper Devonian Middle Frasnian Domanic source rocks consist of
siliceous limestones, shaley dolomites and marls, which contain predominantly sapropelic type I and humic-sapropelic
type II of organic matter. The Domanic facies formed in lacustrine environments and their TOC varies from 0.32 to 7%
and reaches to 22 – 30 %. The reservoirs are associated with Frasnian-Famennian carbonate buildups, where porosity
varies from 7 to 20 % and permeability from 100 to 500 mD.
Upper Frasnian – Lower Carboniferous, Tournaissian and Visean strata, containing more than 2% of the organic
matter, may also be a source rocks. Their organic matter is of type II (humic-sapropelic). These source rocks are identified
in the oil fields within the local Upper Devonian – Lower Carboniferous carbonate buildups in the central part of the
Khoreyver depression (Surkharata, Tedinskoye, North Khosedayu, Sikhorey and others), in the Pechora-Kolva aulacogen
(Kharyaga, Usa and Vozey fields) and in the Varandey-Adzva structural zone (Medyn – more, Toboy and Myadsey).
Other hydrocarbon source rocks for the Pechora offshore are Carboniferous –Lower Permian carbonate shales.
They belong to type II-III; and further to the Barents Sea (Murmanskaya, Severo-Kildinskaya areas), the organic matter
becomes more sapropelic and can be labeled as type II. The Carboniferous – Lower Permian source rocks contain the
lowest percentage of organic matter (TOC varies from 0.32 to – 0.5 %), but the volumes of shale and organic matter are
sufficient for its consideration as a source rocks for the Dolginskoye gas condensate field, Varandey more oil field and SeveroGulyaevskoye gas-condensate field. In the Barents Sea these source rocks may have contributed to the Murmanskoye and
Severo-Kildinskoye gas condensate fields. The porous and void reservoirs are associated with limestone and dolomites. Oil
and gas occur in the Pechora-Kolva aulacogen, the Varandey-Adzva structural zone and offshore the Timan-Pechora. These
source rocks are located mainly in the offshore part of the basin and may have contributed hydrocarbons by lateral migration
from the deepest parts of the basin.
Fig. 3. Main tectonic elements of the north Eurasian basins (Western Arctic and West Siberia)
Stoupakova et al. 2011. Modified from Surkov&Zhero (1981), Kontorovich&Surkov (2000 ), Kontorovich et al. (2001),
Skorobogatov et al (2003), Timonin (1998), Ulmishek (1986), Bogdanov& Khain (1996), Gabrielsen (1990), Johansen
(1994), Brekhuntsov, Bityukov (2005), Rudkevich (1986), Kalenich et al. (2004), Martirosyan, Vasilyeva (2004) and
Bochkarev 2004.
Legend: 1 –extensional depressions/ Palaeozoic (Devonian) intracratonic rift systems with inherited sag basins and
inverted swell: Central Barents, West Siberia, Yenisei-Khatanga, East Ural; 2 – Triassic grabens; 3 - relatively stable areas
of the ancient platform; 4 – Middle Ob platform massif; 5 – syneclise; 6 – monoclines; 7 – inverted swells; 8 –
depressions/extensional basins, overlying older; 9 – domes and uplifts; 10 – 13 fold belts: 10 – Baikalian, 11 –
Caledonian; 12 – Hercynian; 13– Cimmerian; 14 – Triassic intrusions in West Siberia; 15 – oceanic rifting; 16 – rivers; 17
– coastal line; 18 – name of structures, 19 – Seismic profiles; 20 – Oil and gas provinces boundaries.
Core samples of the Lower Palaeozoic and and Upper Devonian-Lower Carboniferous source rocks are considered
representative of the thermally mature organic matter, that constitute source rocks in this succession. They are related to
the middle or end of the oil window - beginning of at the depth below 3000 m (Fig.5). Hydrogen index (HI) varies within
500 – 990 HC mg/g of rocks. Maximum bitumoid is found in the Upper Devonian Middle Frasnian source rocks and it is equal
to 1.1 and 2.0%, bitumoid factor β – 18,7 and 43,6 %. The main oil and gas kitchens are located in the deep parts of the basin, in
the Pechora-Kolva and Varandey-Adzva aulacogens and their extension to the offshore Pechora area, where source rocks have
been matured enough for gas generation. Oil generation from Lower-Middle Palaeozoic source rocks probably started at 270 –
250 Ma during the Late Permian time and continued in the whole Mesozoic time period. Gas generation from these source rocks
probably started 150 Ma in the deepest parts of the basin, but the oil generation had been continued within the whole basin.
№
Age
Thickness, m
Ro, %
TOC, %
Organic
matter type
1.
S1V
20-100
0.85 - 4
0.2-5.0
I-II
2.
S2P
50-300
0.85 - 4
1.0-4.0
I-II
3.
D1l
100-1000
0.8 - 4
0.1-11.6
II
4.
D2-D3f1kn+sr
20-200
0.5 – 2.5
0.2-3.8
II-III
5.
D3f3-C1t
10-300
0.4 - 2
0.5-22.7
I, II
6.
С2-P1ar
50-1000
0.4 – 0.85
0.8-4.0
II-III
7.
P,k-Т
50-70
0.4-0.6
0.2-2.8 (up to
25.0%)
III
Table 1. Main characteristics of the source rock horizons in the Timan-Pechora basin
Fig. 4. Palaeozoic source rocks of the northern Timan-Pechora basin (Stoupakova et al 2011)
Fig. 5. Vitrinite reflectivity index variation with depth
in the Prirazlomnaya and Severo-Gulyaevskaya areas
Fig. 6. Modified Van-Krevelen diagram for the
Barents sea Carboniferous – Lower Permian strata
The Carboniferous – Lower Permian source rocks penetrated in the Pomorskoye and Prirazlomnoye fields at
2600-2900 m depth are located in the oil window. Their maturation is various in different parts of the Pechora offshore
achives the maximum in the eastern parts of the Pechora sea, adjacent to pre-Paikhoy foreland. The mixed type of the
Lower Permian organic matter is confirmed by the distribution of n-alkanes and isoprenanes in chloroform extracts in
Severo-Dolginskaya and Dresvyanskaya areas. The chromatograms have bimodal distribution of n-alkanes: the first peak
is in С17-С19, the second one – in С27-С28 and С29. Pristane/phitane coefficient is >1, which is evidence of dominant of
humic organic matter. In the Dresvyanskaya area this ratio is 2, in Severo-Dolginskaya area it is 1.3. Lower Permian
Asselian–Sakmarian and Artinskian source rocks are in the beginning of the oil window. They have not been matured
enough to produce substantial quantities of oil (fig. 6).
Barents Sea Petroleum Systems.
Nowadays HC discoveries in the Eastern Barents Sea are connected mainly with the Triassic and Jurassic
reservoirs. In the South Barents Sea, the Middle and Upper Triassic strata can be considered as oil and gas source rocks
with prevailing gas potential. The Middle Triassic strata are represented mainly by multi-colored shales with interbeds of
siltstones and sandstones. The shales comprise organic matter with TOC from 0.15% in the Severo-Kildinskaya well to
1.17% in the Pomorskaya well. The organic matter is associated with humic detritus, less often – with calcareous algae
(Severo-Kildinskaya area). Rock-Eval pyrolysis data show organic matter of various types (I, II, III and transient II-III)
(fig. 7).
In the northern part of the Barents Sea, Middle Triassic succession was accumulated in proximately deep shelf
environments. The total thickness of the Middle Triassic succession on the Frantz-Josef Land attains almost 1600 m
(Gram-Bell Island) and 1950 m (Hayes Island).The Middle Triassic formation consists of dark-gray and black bituminous
shale unites with TOC from 1 to 11 %. The average TOC is 1.6 – 2 %. The highest concentrations of organic matter are
observed in the Middle Triassic Anisian shale in Svalbard Archipelago, where Middle Triassic shales from outcrops at the
Spitsbergen Archipelago are very rich: (S1+S2), attaining 57 mg HC/g rock. The organic matter of Triassic source rocks
is mainly humic in the eastern Barents Sea (type III) and mixed in the northern and western Barents (type II and III).
The Lower and Middle Jurassic source rocks are represented by lacustrine and shallow marine shales with good
source potential and proven productivity occurred in the Shtokman field. They consists of dark-gray claystones and lightgray coarse-grained siltstones. The mica grains and inclusions of the vegetative detritus are seen at the boundaries of the
interlayers. Rock Eval kinetic parameters show the ТОС of the humic-sapropelic type II-II varying within 0.5 - 3.1% (Fig.
8). The Upper Jurassic strata are very rich, but not matured enough in the Barents Sea basins. They consist of dark
colored, black shales with high content of organic matter. The Upper Jurassic source rocks have been studied from the
Spitsbergen Archipelago, Shtokman and Snohvit gas condensate fields, where core samples contain organic matted of
mixed humic-sapropelic type II and II-III with TОС from 1.4 to 28.2 %. The Hydrogen index (HI) varies from 83 to 279
mg HC/g TOC. The source rock samples from the Spitsbergen Archipelago have TOC=2.5-6%. Their HI is 31-158 mg
HC/g TOC. The Upper Jurassic source rock samples from the Snohvit field have TOC -1.5-28% and HI - 61-171 mg
HC/g ТОС. The samples from the Shtokman field contain TOC - 8-9.5% and their HI - 360-370 mg HC/g TOC – the
highest values for all studied Upper Jurassic samples.
The maturity of the Triassic source rocks is very different, because the depth of the Triassic succession varies
from 2-3 km up to 7 km.. In the deepest parts of the Barents Sea these source rocks have already over-matured and passed
the oil and gas window. In the other area they can be a good oil and gas source rocks. Based on the available rock sample
from Spitsbergen and the Frantz-Josef Land Archipelagos and core data from Barents Sea wells the Triassic strata are
matured quite enough to generate hydrocarbons. Most of the core samples of the Triassic source rocks are considered
representative of the oil window (Тmax=430-445оС) (Fig. 7). Some samples from the south-west of the Russian Barnets
Sea, in the Severo-Kildinskaya -80 well (1410 – 1480 m interval) show immature Middle Triassic organic matter. The
migration hydrocarbon index (S1) is low (0.09 – 0.14 mg HC/g rock). The residual generation potential varies from 0.42
to 1.52 mg HC/g rock. Probably the Middle Triassic source rocks had been supplying gas for the huge gas pools in
Triassic and Jurassic reservoirs of the Barents Sea.
The maturation of the Lower –Middle Jurassic rocks, defined by Tmax=431˚C, corresponds to the initial stage of
the main oil and gas window (Ro = 0.4-0.5 %) (Fig.8). These source rocks have a high generation potential (S1+S2),
which varies from 1,54 to 8.96 mg HC/g rock) (Table 2). Upper Jurassic source rocks can be divided into two groups.
Group I includes immature source rocks, which samples have low Тmах and high HI. These samples were taken from the
Shtokman field and from Severo-Murmanskaya and Arkticheskaya wells. Their average Тmax is 414-417oC and HI is
362-368. These core samples are considered representative of the thermally immature organic rich source rocks with
organic matter of the mixed sapropelic-humic type II. Group II corresponds to poor mature source rocks of the mixed
sapropelic-humic type II-III, which are in the beginning of oil window. This group includes samples from Spitsbergen and
Snohvit field (Norwegian sector) with the average Тmax and HI are 426 - 473oC and 63 -171 mg HC/g TOC respectively.
Sampl
e No.
Rock
Age
Tmax
S1
S2
S3
S1+S
2
PI
S2/S3
RC
TOC
HI
OI
1
Claystone
J2a1
441
0.18
3.29
0.96
3.47
0.05
3.43
1.78
2.11
156
45
2
Claystone
J2a1
443
0.1
1.44
1.19
1.54
0.07
1.21
1.15
1.33
108
89
3
Claystone
J2
435
0.08
2.02
0.39
2.1
0.04
5.18
1.14
1.33
152
29
Claystone
J3-K1
(K1)
427
0.01
0.18
0.18
0.19
0.07
1.00
0.56
0.59
31
31
5
siltsones
J2
432
0.25
2.49
0.54
2.74
0.09
4.61
1.24
1.5
166
36
J 13
6
claystones
and
siltstones
431
0.58
8.38
0.44
8.96
0.07
19.05
2.31
3.08
272
14
4
Table 2. Rock-Eval data of the Lower-Middle Jurassic samples from the Barents Sea
Fig. 7 Modified Van-Krevelen diagram for the
Barents sea Triassic deposits
Fig. 8 Modified Van-Krevelen diagram for the
Barents sea Jurassic deposits
The processes of HC generation started in the Barents sea at the beginning of Early Triassic within the deepest
parts of the basin, where Palaeozoic source rocks, analogies to the Timan-Pechora basin’s source rocks could generate
hydrocarbons. They had almost realized their potential by the Middle Triassic time. Late Triassic is characterized by
intense vertical and lateral migration of hydrocarbons (Fig. 9). Hydrocarbons were moving form the deepest parts of the
basin to its flanks. Triassic source rocks started generating HC 120 – 100 Ma, in Early Cretaceous. By the Late Cretaceous
Triassic source rocks had realized its potential to 90 % in the central part of the South Barents depression. On the flanks
these source rocks have just entered the oil window, and their degree of catagenetic conversion has not exceeded 40-50%
by the end of Cretaceous period.
Fig. 9. Oil-and-gas kitchen in the South Barents Sea and hydrocarbons migration at the present-day phase.
3. Yamal-South-Kara Petroleum Systems
In the northern West Siberia Jurassic and Cretaceous shales and coaly formations thought to have sourced most
known petroleum there. The Palaeozoic and Triassic source rocks were poorly studied. Individual geochemical studies of
terrigenous-carbonates from Palaeozoic samples on the Yamal Peninsula showed TOC variations from 0.1-0.2% to 2.63.0%. TOC content in the Palaeozoic terrigenous rocks are 0.8-3.5%. The Triassic source rocks strata (Tampey series) are
penetrated by a few wells mainly in the north of the West Siberian basin. The most detailed data on the Triassic source
rocks were obtained in the Tyumenskaya superdeep well (SG-6). The TOC content in some organic-rich shaly intervals
varies from 3 to 5%. However, in most of the area the Palaeozoic and Triassic source rocks occur at great depths and overmatured. Its Rock-Eval index (S1+S2) varies from 0.13 to 0.44 mg HC/g of the rock and НI is 2-34 mg HC/g of TOC.
Lower-Middle Jurassic and Upper Jurassic-Lower Cretaceous source rocks supply the most oil and gas for the
northern West Siberia fields. Upper Cretaceous source rocks generate predominantly gas. The source rocks in the LowerMiddle Jurassic strata are shaly-coaly and coaly layers of the Tyumen formation and shales of the Togur formation. They
are organic-rich with the average TOC of the mixed type II-III from 1 to 5%; (fig. 10). The Tyumen and Togur formations
are thermally mature for oil generation in the most parts of the West Siberia basin. The vitrinite reflectance (Ro %)
reached 0.8%. In the Yamal and Gidan peninsular their analogues are the shales and coaly formations of the
Bolshekhetskaya stratigraphic unit. The average TOC content in the Lower-Middle Jurassic strata is 1.92%, increasing
towards the Kara Sea offshore area. The source rocks contain the organic matter of humic type III). Though, in some
samples the organic matter of Type III-II or II is marked. The hydrogen index (HI) varies from 200 to 285 mg HC/g of
TOC; Tmax - (445-460о С) correspond to the middle and final stages of the oil window.
The Upper Jurassic marine shales are the principle source rocks for most of the oil and probably of the gas in the
West Siberia basin. They comprise organic rich shales of Volgian to Berriassian age (Bazhenov formation). The sediments
were deposited in a proximately deep-water marine basin during the most extensive Late Jurassic transgression. The
organic matter in the Bazhenov Formation is derived from plankton and bacteria, so the kerogen is of type II (fig. 11). The
average TOC content in the formation is 5.1%, increasing in the southern direction to 9-11% (Middle Ob area). Over the
most part of the West Siberian basin maturation of the Upper Jurassic source rocks corresponds to the peak of the oil
window. The highest maturity is found in the Middle Ob area (Ro = 0.7 – 1.1 %) and in the north of the Nadym-Pur
petroleum region (Ro > 1.1 %). Towards the marginal areas of the basin the maturation of the Upper Jurassic source rocks
decreases. As the maturity increases, HI decreases from 400-500 mg HC/g of TOC at the initial stage of the oil window to
100-200 mg HC/g of TOC at its final stage. In the northern areas of the basin (Yamal Peninsula), the TOC content in
Bazhenov formation increases toward the Kara Sea from 0.9% (Neitinskoye field) to more than 4.0% (Kharasaveyskoye
field); HI varies from 230 to 270 mg HC/g of TOC, Tmax=440-460 оС.
Fig. 10 Modified Van-Krevelen diagram for the Yamal
peninsula Lower-Middle Jurassic deposits
Fig. 11 Modified Van-Krevelen diagram for the
Yamal peninsula Upper Jurassic deposits
The marine Neocomian Achimovskaya and Tanopchinskaya formations are the source rocks for most of the gas
fields in the northern Yamal and probably Kara Sea. The source rocks are represented by shales and coaly rocks, with
average TOC is about 4-5%. The highest TOC values are measured in shales of the Kharasaveyskoye field (5.6%), the
lowest – in the Novoportovskoye field (1.04%). Neocomian source rocks contain humic organic matter of type III and
their maturation corresponds to initial stage of the oil window (Тmax = 432-456оС) (Fig. 12).
Albian-Cenomanian strata are productive mainly in the northern areas of the basin, where the giant gas pools
associated with them. This interval of the section correlates with the Pokurskaya formation in the central part of the West
Siberia basin and with Maressalinskaya formation – in the Yamal-Kara and Gydan region. Both formations are
represented by sub-coal-bearing, continental and nearshore-marine deposits. Maximum concentrations of TOC (up to
6.4%) are located in the northern part of the Yamal Peninsula. The organic matter type is clearly established as type III.
The Albian-Cenomanian source rocks in the northern areas of the West Siberia are thermally matured for initial stage of
oil generation.
Fig. 12. Modified Van-Krevelen diagram for the Yamal peninsula Lower Cretaceous deposits
The main source rocks of the northern West Siberia and their maturation have been used for basin modeling of
the offshore Yamal and Gidan peninsulas and adjacent parts of the Kara Sea area. The Jurassic oil and gas source rocks in
the Kara Sea offshore area have attained the oil window by the end of the Aptian age (K 1a – 112 Ma). By the end of the
Eocene age, the Lower Cretaceous source rocks were also involved into the oil window (Fig. 13). The AlbianCenomanian source rocks are entering the oil window only at present time; this is shown in Fig. 13. The Lower and
Middle Jurassic source rocks entered the oil window in the Hauterivian time (135-130 mln. years ago); at present, they are
in the gas-generating stage and apparently are not very interesting as the oil sources. The Upper Jurassic source rocks
entered the oil window in the end of the Aptian time (112 mln. years ago); at present, they are in the final oil-generating
stage. The Cretaceous source rocks are most prospective in the Kara Sea; they are in the beginning (Albian-Cenomanian
rocks) and in the peak (Neocomian rocks) of the oil window, and are the main hydrocarbons’ sources in the Kara northern Yamal region (Fig.14).
Fig. 13. Evolution of the organic matter maturation (based on the basin modeling results)
Fig. 14. Oil-and-gas kitchen in the South Kara Sea and hydrocarbons migration at the present-day phase.
The Lower and Middle Jurassic source rocks at present have realized their generating potential practically in full
everywhere along the studied profile. The Upper Jurassic source rocks have not realized their potential yet in the uplifted
areas, like megaswells and other large uplifts in the Kara Sea. Neocomian and Albian-Cenomanian strata have realized
just a small pat of their potential, and are the most promising strata to generate new hydrocarbons.
3. Yenisey-Khatanga Basin petroleum system
The Yenisey-Khatanga basin contains small oil and gas fields in Mesozoic and Palaeozoic successions. Mesozoic
petroleum systems are associated with the centrsal part of the basin, while the Palaeozoic and Riphean petroleum systems
are productive in its flanks. In this study we have evaluated core samples of the Mesozoic source rocks from the wells of
the central part of the basin and the Palaeozoic source rocks’ samples from the eastern flank of the Yenisey-Khatanga
basin, the Anabara-Khatanga saddle.
The only sample of the Riphean age is represented by a black mudstone with maximum content of TOC - 6.02%.
The sample was taken in the Khorudalakhskaya-1 well from 2.8 km depth. The Riphean source rocks are thermally overmatured. Their Tma is 500 оС. The present-day value of the hydrogen index is so low (18 mg HC/g Corg) and their
generation potential is 1.71 mg HC/g Corg; the rock belongs to lean source rocks strata. Palaeozoic core samples contain
organic matter with TOC from 0.01 – 5.6 %. (Fig. 15).The Cambrian source rocks are represented by mudstones, shales
and limestones. They comprise organic matter with TOC from 0.21 to 3.14%, but prevailing values are 0.2-0.3%. The
highest hydrogen index for non-matured samples is 38 mg HC/g Corg. Generation potential values (S1+S2) vary from
0.04 to 1.48 mg HC/g Corg with prevailing values <0.2 mg HC/g Corg. The only examined sample of the Carboniferous
age was taken in Yuzhno-Suolemskaya-10 well at the depth of 2.4 km. It represents gray pelitomorphic limestone with
TOC 0.04%. Its calculated Tmax is 302 оС means that this sample is poorly matured, it has not yet entered the main oil
window. It is also confirmed by relatively high hydrogen index HI = 150 mg HC/g Corg; this indicates that sapropelic
component is more important in the initial organic matter composition, than it is in the organic substance of Permian
strata. Generation potential of this sample is extremely low and is equal to 0.12 mg HC/g Corg.
Fig. 15 Modified Van-Krevelen diagram for the Yenisey-Khatanga Palaeozoic deposits
The Lower Permian 22 core samples of mudstones contain organic matter with TOC from 0.01% to 5.1%. The
Lower Permian potential source rocks have been penetrated by wells at the depth from 1140 m in Gurimisskaya-1 well to
3000 m in Vostochnaya-1 well (Lower Kozhevnikovskaya Formation). Maturation of the core samples from the different
depth varies a lot. Their calculated Tmax varies from 302 to 534 оС., but the most of the samples are within 435-460 оС
interval, which corresponds to the main oil window. Generation potential values (S1+S2) vary from 0.23 to 7.78 mg HC/g
Corg. Most of the examined samples have generation potential <2 mg HC/g Corg.
The Upper Permian strata are represented by a single sample of the Misailapskaya formation from
Volochanskaya-1 well. Its organic carbon content is equal to 1.93%. In general, the sample is similar to the Lower
Permian strata, described before. Currently the Lower Permian strata are in the oil window (Tmax = 444 оС). Present-day
hydrogen index HI = 55 mg HC/g Corg, and its value, converted to the beginning of catagenesis, is equal to 110-120; this
permits to assume predominantly humus origin of the initial organic matter. Generation potential value is equal to 1.17 mg
HC/g Corg. Rocks refer to the category of lean gas source strata. Qualitative type of the organic substance from the
Palaeozoic strata, determined using the pyrolytic analysis data, is predominantly humus or mixed sapropelic-humus. The
Lower Permian strata have the best quality among Palaeozoic formations.
The Middle Jurassic strata are the best in terms of the oil generating aspects among the Mesozoic formations
(Logatskaya-361, Zapadno-Kubalakskaya-359 wells). The studied Palaeozoic and Mesozoic strata occur at various depths;
due to that their organic matter is in different maturation rates stages – from non-matured Tmax=302оС to stronglymatured Tmax=534оС. Present-day depths of the strata occurrence do not reflect the maturation rate of the organic matter;
this is associated with various intensity of erosion during certain stages of the Mesozoic – Quaternary history of the basin
development.
Baisn modeling of hydrocarbon generation and migration has been done for the profile, crossing the eastern flank
of the Yenisey-Khatanga salt basin, Anabar-Khatanga saddle. Lower Permian source rocks started to generate
hydrocarbons in the Early Triassic time within the central parts of the basin; generating of hydrocarbons in the marginal
parts of the basin started later – in the Middle Triassic time. By the end of Triassic period, all Palaeozoic source rocks
were in the oil window. At present day the most part of the formation is in the oil generating stage (Ro = 0.85-1.15%), and
in the central part of its salt basin – in its final stage or in the early stage of gas window (Ro = 1.15 – 2%) (Fig. 16).
Fig. 16 .Present day oil window position.
In the central part of the salt basin, Upper Devonian –Lower Carboniferous and Cambrian oil source rocks
attained oil window by Early and Late Permian time. Upper Riphean oil source rocks entered main gas window at the end
of Carboniferous period. The most ancient Middle Riphean oil source rocks started to generate hydrocarbons yet in
Silurian time. At present, Riphean strata are capable to generate gas only in the marginal parts (Ro = 1.15 – 2%), while
their potential is already completely realized in the central part of the saddle. In the north-eastern sector of the profile
besides oil source rocks of the Lower Kozhevnikovskaya formation, the Upper Devonian oil source rocks probably are in
the final oil-generating stage and can also supply liquid hydrocarbons (fig. 17). The transformation ratio of the organic
matter is pretty high. The potential of the Lower Kozhevnikovskaya source rocks grows from the first percents in the area
of the Northern Siberian monocline to 90% in the central part of the saddle (Kharatamusskaya Depression).
Due to the absence of regional caprocks and reservoir properties of the given lithotypes, hydrocarbons are
distributed over the whole sedimentary stratum according to the modeling results, but the saturation rate does not exceed
several first percents. The most interesting are hydrocarbons accumulations in the Lower Devonian sub-salt complex’s
carbonaceous-halogen stratum, in the Lower Carboniferous carbonates, and in the Lower Permian terrigene complex,
where saturation is 50% and more. All reservoirs are confined mainly to anticline traps. Fault-bounded reservoirs can
occur in the area of the salt dome. The vertical migration of hydrocarbon fluids dominates mainly in the central part of the
anticline; and by contrast, their lateral migration dominates in the marginal parts (from the deepest central area of the
saddle) (fig. 18).
Fig. 17 Evolution of the organic matter maturation based on the basin modeling results (Location of «wells» see on fig.
15)
Based on the modeling the main possible gas accumulations are concentrated deeply in the sub-salt complex,
located in the central part of the salt basin. In zones, where hydrocarbons can migrate upwards the section (mainly in the
zones of fault tectonics) they refill potential pools of the above-salt complex. The Lower Kozhevnikovskaya formation
and the deeper Upper Devonian – Lower Carboniferous siliceous-carbonate strata are the main suppliers of predominantly
oil together with gaseous hydrocarbons in the above-salt complex of the central part of the trough. Possible accumulations
of hydrocarbons can be expected in the anticline structures; most interesting of them are the uplifts of BelogoroTigyanskaya zone and arched uplift, separating the salt basin of the Anabar-Khatanga saddle from the pre-Taimyr foldthrusted zone. Besides that, fault-bounded traps close to salt stocks can have high oil potential (Nordvik field). In the
south-western part of the studied area (the slope of the Anabar anteclise), the potential hydrocarbon leads will be similar
to petroleum plays of the Eastern Siberia, where the main source rocks are located in the Riphean complex and in the
Middle Cambrian formations.
Fig. 18. The direction of migration.
Conclusions
Although a wide variety of potential source rocks, ranging in age from Proterozoic to Mesozoic, have been identified in
the Western Russian Arctic basins, most of the petroleum discovered – the proven petroleum systems - is derived from a
few narrowly defined stratigraphic intervals: Devonian, Triassic and, especially, Jurassic are the most important.
Palaeozoic petroleum systems have been explored mainly in the Timan-Pechora and Yenisey-Khatanga basins. The
Mesozoic petroleum system are very productive in the Kara-Yamal and Barents Sea basins where they supply a huge
volume of hydrocarbons. Hydrocarbon generation started long before the present basins’ structural configuration formed,
and oil and gas kitchens were associated mainly with extensional parts of the basins. Later phases of rifting and extension
affected both the ancient oil and gas kitchens and the younger ones. Inversion caused trapping and affected fluid
migration, mixing the petroleum systems.
Acknowledgements
We would like to thank the Russian-Norwegian collaboration for supporting this work during a period of more
than 5 years. Statoil ASA is acknowledged for funding the Moscow State University and Tromso University cooperation.
Thanks Sevmorgeo, SMNG, MAGE and Yuzhmorgeologiya for being allowed to use regional seismic profiles,
GAZPROM-VNIIGAZ for core material for this evaluation. We offer our sincere thanks to Anthony Spencer, Erik
Henriksen and John K Milne for valuable input in our work.
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